1. Field of the Invention
The present invention relates broadly to apparatus and method for investigating subsurface earth formations. More particularly, the present invention related to borehole tool and methods for improving the determination of at least one multiphase flow parameter of a formation traversed by a borehole. For purposes herein, the term “borehole” when utilised by itself or in conjunction with the word “tool” is to be understood in its broadest sense to apply to partly-cased and uncased boreholes and wells.
2. State of the Art
The determinations of multiphase flow parameters, like relative permeability and other hydraulic properties of formations surrounding boreholes such as capillary pressure are very useful for analyzing, through simulation or analytical techniques, multiphase fluid flow in reservoirs, and in obtaining an overall understanding of the structure of the formations. For the reservoir engineer, relative permeabilities are generally considered to be fundamental reservoir multiphase properties, the determinations of which is next only in importance to the determination of porosity, fluid saturations, formation pressure and permeability. Indeed, determinations of relative permeabilities to oil and water are crucial for forecasting oil recovery during water flooding or natural water drives. The economic viability of a reservoir therefore depends upon the nature of these saturation dependent permeabilities. Capillary pressure determines the original phase distributions in reservoirs and to some extent affects the movement of fluids across the reservoir strata. The movement of the fluids however is largely determined by the single phase and relative permeability.
Before production, when obtainable, cores of the formation provide important data concerning permeability, capillary pressure and relative permeabilities. However, cores are difficult and expensive to obtain, and core analysis is time consuming and provides information about very small sample volumes.
Aside from being an expensive proposition, several serious drawbacks to using core-plugs cannot be overlooked. Firstly, core plugs used in the laboratory experiments usually are limited to an inch or two lateral to the wellbore. Therefore, cores do not normally capture properties on a scale relevant to fluid displacement in a reservoir. Measured properties suffer from inaccuracies introduced in the laboratory that are all too common in relative permeability experiments. Furthermore, data has to be scaled up from inch scale onto grid block scale in the simulation model which can be of the order of tens of feet in the vertical direction (normal to the bedding pane) and hundreds of feet in the horizontal direction. These large simulation blocks contain heterogeneities that are not included in the original core measurements.
Even if one obtains fine-scale core data, upscaling methods are notoriously unreliable and are imperfect. There is no guarantee that any such scale-up will be reliable in strongly heterogeneous reservoirs, especially carbonates. A better solution, yielding measured properties at a scale useful for making improved predictions is therefore highly desirable.
Additionally, the retrieved cores for laboratory experiments may not be representative of the reservoir rock due to permanent changes in wettability, pore structure, and physics and chemistry of fluid interactions during coring, transportation, cleaning and restoration. The properties of formation fluids may also change after they are lifted from the reservoir to the surface. In view of this, a technique that can provide measurement or estimate of in situ petrophysical properties is necessary.
Furthermore, coring, core handling and surface laboratory work are very time-consuming and expensive. For example, restoration of the core to original wettability conditions after cleaning contaminations resulting from drilling fluids often requires as long as 1000 hours of aging. Furthermore, each core has to be measured individually for all required properties. To cover the entire formation thickness of highly heterogeneous carbonate reservoirs, significant amount of laboratory work must be done. These limitations lead to the prolonged data processing time from core collection to result presentation. Hence, a more reliable, faster, simpler and cheaper technology is needed in obtaining the relative permeability and capillary pressure.
Co-owned U.S. Pat. No. 5,335,542, which is hereby incorporated by reference herein in its entirety, proposed to characterize formation properties by combining probe pressure measurements with resistivity measurements from electrodes mounted on the pad in wireline formation tester. As fluid is withdrawn or injected into the formation at known rates, the fluid pressure of the formation is obtained, and electromagnetic data is obtained by the electrodes. The electromagnetic and fluid pressure data are then processed using various formation and tool models to obtain relative permeability information, endpoint permeability, wettability, etc. While the tool and method of co-owned U.S. Pat. No. 5,335,542 is believed to be effective in providing important relative permeability and other information, it will be appreciated that in order to gather information from which the desired determinations are made, the borehole tool must be in contact with the formation. Thus, the data gathering process is time consuming and data is limited to specific locations, although information regarding other locations can be generated from the data obtained at the specific locations. In addition, while some depth of investigation is obtained, the interpretation does not extend to a reservoir length scale.
It is also possible to obtain formation properties related to multiphase flow, such as relative permeability and fractional flow function, from the acquired data using techniques outlined by co-owned U.S. Pat. No. 5,497,321, which recites an open hole logging tool capable of providing a log of fractional flow characteristics of formations surrounding an earth borehole or by co-owned U.S. patent application Ser. No. 11/854,320 titled “Petrophysical interpretation of multipass array resistivity logs obtained while drilling” which recites the stacking of single pass resistivity data with different depths of investigation obtained during different passes such that this stacked data may be jointly inverted. These aforementioned references are herein incorporated by reference in their entirety. However, because of the small diameter of probes and electrodes, and short spaces between coils used in the invention, the U.S. Pat. No. 5,497,321's technique limits the depth of investigation to just a few feet.
To circumvent the small scale limitation of wireline formation tester, a technique that uses pressure and resistivity measurements along with a water injection/fall-off test has been proposed by co-owned U.S. Pat. No. 6,061,634, which is hereby incorporated by reference herein in its entirety. This invention utilizes a pressure sensor, a flow meter and multiple ring-shaped electrodes mounted on the peripheral surface of a wireline tool body along its axial direction to measure pressure, flow rate and electrical data during water injection when the tool is set in the borehole opposite the formation to be investigated.
The pressure signal can be used to infer the mobility of the fluids in the formation based on well-established pressure transient test theory for injection/fall-off test. The interpretation of electrical data is a variant of the method of U.S. Pat. No. 5,497,321. This technique is an in situ technique to quantify dynamic reservoir properties; it can obtain results much faster than core experiments, and the resulting properties are measured at a similar scale to that used in the reservoir simulations. Therefore, it is an appropriate method for dynamic reservoir evaluation. The method however has to make some assumptions with regard to the shape of the relative permeability curves for the inversion. The technique that relies on pressure alone also has uncertainty resulting from unknown skin related near wellbore damage.
In view of the above, a system, apparatus and method for improving the sensitivity of combined pressure and resistivity inversion, given the low radial resolution of an electrical measurement from a borehole is required. Indeed, it has been recognized that in the displacement of oil by brine, the salinity front carries with it a strong resistivity variation and is more easily detected than subtle resistivity profile changes behind a saturation front within the formation. Furthermore, the movement of strong resistivity changes associated with the salinity front carries with it information regarding the fractional flow characteristics of the formation.